Foaming agents for use in coal seam reservoirs

ABSTRACT

A well treatment fluid composition that comprises a carrier fluid and an amphoteric surfactant, and optionally a viscosifying agent and proppant, is well suited for use in fracturing coal beds to stimulate methane production. The composition preferably is a foam that comprises a gas such as nitrogen or air. Preferably, the surfactant has the formula 
     
       
         R—NH 2 —(CH 2 ) n —C(O)OX 
       
     
     wherein R is a saturated or unsaturated alkyl group having from 6-20 carbon atoms, n is from 2-6, and X is hydrogen or a salt forming cation.

CROSS REFERENCE TO RELATED APPLICATION

This application is a Continuation-In-Part of Ser. No. 09/513,429 thatwas filed on Feb. 25, 2000, now abandoned.

TECHNICAL FIELD OF THE INVENTION

This invention relates to the recovery of natural gas from coal seamsand, more particularly, to a well treatment fluid and method ofstimulating gas production from subterranean coal beds by hydraulicfracturing.

BACKGROUND OF THE INVENTION

Subterranean coal beds often contain large quantities of methane. Thepresence of methane in these subterranean coal deposits presents asafety hazard in coal mining operations, but also presents anopportunity for recovery of a valuable fuel. In the past, coalbedmethane was often vented to the atmosphere or flared to reduce thesafety risk in mining. More recently, in order to minimize air pollutionand maximize economic return from coal bed operations, there has been anincreasing focus on recovering methane rather than venting or flaringit. The recovery of coalbed methane is typically accomplished bydrilling and completing a gas well into the coal seam and fracturing thewell within the coal formation to enhance methane recovery.

Hydraulic fracturing methods for oil and gas wells drilled in a hardrock formation involve injecting a fracturing fluid (e.g., an aqueousgel or an aqueous foam) through the wellbore and against the face of thesubterranean formation at pumping rates and pressures sufficient tocreate or extend cracks in the formation. Typically a proppant (e.g.,sand or bauxite) is mixed with the fracture fluid and is carried by thefluid into the fractures. When the pumping rate and pressure arereduced, the fractured formation settles back onto the emplacedproppant, and the proppant holds the fractures open sufficiently toestablish a permeable fluid communication channel from the tip of thepack of proppant back to the wellbore.

Fracture stimulation of coalbed methane reservoirs requires techniquesquite different from those used in conventional hard-rock reservoirs.The methane in a coal seam is adsorbed to the surface of the coal. At acertain pressure, governed by the Langmuir desorption isotherm, themethane will begin to desorb from the coal. In addition, coal seams areoften completely saturated with water. In these cases, large quantitiesof water must be removed in order to lower the reservoir pressure to apoint below the methane desorption pressure. Therefore, a hydraulicfracturing treatment in a coal seam must be designed to produce watereffectively.

Maintaining the coal in an oil-wet state facilitates water production.This is because coal is soft and friable. Wells are generally producedat maximum pressure drawdown to reduce the reservoir pressure as quicklyas possible. The proppant particles (usually sand) become embedded intothe fracture faces due to the increase in closure stress created by thehigh drawdown pressure. Proppant embedment causes a large quantity ofcoal fines to be produced. If these fines are water-wet, then they willbe easily transported in the water phase during dewatering of the coalbed. The fines will then migrate into the fracture, eventually causingsevere reduction of the fracture conductivity. It is therefore importantto maintain the coal fines in an oil-wet state, so they will tend toclump together in the presence of water, thereby greatly reducing theirmobility. This concept is also critical in the natural fracture (cleat)system of the coal adjacent to the hydraulic fracture. Coal fines willbe generated due to shrinkage of the coal, oxidation, etc. These finescan cause plugging of the cleat system, which severely reduces the wellproductivity and ultimate gas production.

Additives exist that can provide good oil wetting of coal. For example,superior oil wetting in the presence of water can be achieved by methodsand materials described in U.S. Pat. No. 5,229,017 (Nimerick andHinkel). One such commercially available surfactant, denoted surfactantA herein, (available from Schlumberger), comprises a branched tridecylalcohol with seven moles ethylene oxide (EO) and two moles butyleneoxide (BO).

Foamed fracturing fluids are often preferred over non-foamed fracturingfluids in coal seam reservoirs in order to minimize the damageassociated with the natural polymers typically present in the basefluid. Nitrogen is most often used as the gaseous phase in the foamfracturing treatments. However, materials that act as good oil-wettersfor coal have been proven ineffective in providing stable aqueous foams.For example, surfactant A acts as an anti-foaming agent.

There is a need for improved fracturing fluids and methods that aresuitable for use in coal beds to stimulate production of methane.

SUMMARY OF THE INVENTION

The present invention relates to a well treatment fluid composition thatcomprises a carrier fluid, a viscosifying agent, an amphotericsurfactant, and proppant. This fluid composition is especially wellsuited for use in fracturing gas wells in coal beds and is preferablyused in a foam form, that is further comprising a gas such as nitrogenor air.

Preferably, the surfactant comprises an alkyl-aminocarboxylic acid orcarboxylate, that is a zwitterionic compound of formulaR—NH₂—(CH₂)_(n)—C(O)OX, where R is a saturated or unsaturated alkylgroup having from 6-20 carbon atoms, n is from 2-6, and X is hydrogen ora salt forming cation. In various specific embodiments of the invention,n can be from 2-4; and R can be a saturated or unsaturated alkyl grouphaving from 10-16 carbon atoms. More preferably, the surfactant is analkyl-aminopropionic acid or propionate (n=2). One particular preferredsurfactant is coco-aminopropionate, of formula RNH2CH2CH2COOX, where Ris dodecyl, tetradecyl or hexadecyl, with a distribution of aboutdodecyl (C12), 40%, tetradecyl (C14), 50% and hexadecyl (C16), 10% and Xis for example sodium.

The viscosifying agent can be, for example, a solvatable, crosslinkablepolymer selected from the group consisting of guar, hydroxypropyl guar,carboxymethyl guar, carboxymethylhydroxypropyl guar, hydroxyethylcellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose,xanthan, and mixtures thereof.

The can also include a crosslinking agent, a gel breaker for theviscosifying agent, and one or more other additives.

Another aspect of the present invention is a method of hydraulicallyfracturing a subterranean coal bed. This method comprises the step ofinjecting a well treatment fluid composition via a wellbore into asubterranean coal bed at a flow rate and pressure sufficient to produceor extend a fracture in the formation. The well treatment fluidcomposition can have the components described above. Alternatively, thefluid composition used in the method can be free of the viscosifyingagent and/or proppant.

The present invention provides a remedial treatment of coalbed gas wellsto enhance dewatering and the production of gas. The invention is usefulboth for fracturing newly drilled wells and for workover of existingwells (e.g., remedial fracturing of a well that has been producing forsome time and has already been fractured in the past).

The surfactants used in the present invention have good oil wettingcharacteristics in the presence of coal, and are effective foamingagents. Thus, these surfactants are capable of creating a stable, foamedfluid, using either freshwater or brine, while maintaining the naturalsurface properties of the coal, and can minimize the mobility andmigration of coal fines, thereby preserving fracture conductivity andcleat permeability. Additionally, the stability of foams formed withthese surfactants should decrease with pH, which will facilitate cleanup of the foam after the fracturing treatment (i.e., clean up can beperformed with a reservoir fluid having a pH lower than the pH of thefoam).

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1-4 are graphs showing the change in permeability of a bed of coalparticles after different fluids were passed through the bed.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

To recover natural gas, principally methane, from a subterranean coalreservoir, a wellbore is drilled to the subterranean coal seam, andcompleted and perforated (or, alternatively, completed with a slottedliner, or completely open hole) in a manner similar to the procedureused for drilling and completing a normal subterranean gas well in ahard rock formation. The formation can then be fractured to stimulateproduction of subterranean fluids (liquids and gases).

Fracturing fluids typically comprise an aqueous liquid carrier fluid,which is commonly viscosified to improve its rheological andproppant-carrying properties. A preferred fracturing fluid of thepresent invention comprises an aqueous carrier fluid (e.g., brine), asolvatable and crosslinkable polymer to provide increased viscosity, atleast one surfactant, and proppant. Suitable solvatable polymers includeguar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxypropylguar, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose,hydroxypropyl cellulose, xanthan, and mixtures thereof. Cross-linkingagents, such as borates, titanates, zirconates, and/or aluminates, canbe included in the composition, to cross-link or gel the polymer, inorder to increase their proppant-carrying capacity and improve theirrheological properties. Optionally, an agent to delay cross-linking,such as chelants or ligands (e.g., functionalized amines, such astriethanolamine, or functionalized carboxylic acids, such as citricacid) can also be included. The composition can also comprise gelbreaking agents, such as ammonium persulfate (oxidizers), in order tobreak the viscous gels and assist in the return of the fracturing fluidsto the wellbore once the fracturing operation has been completed.Generally, delay agents will not be needed for a foam.

The fracturing fluid composition contains at least one surfactant thatwill keep coal fines oil-wet and is an effective foaming agent.Coco-aminopropionate is one suitable example of such a surfactant.

These surfactants are zwitterionic in nature. Foam prepared usingfreshwater or a KCl brine will possess a neutral pH. Often the pH of thewater in a coal seam is less than 7. The zwitterionic nature of thesefoaming agents will causes the foam to be less stable as the pH of thefluid is lowered. Hence, contact with formation water will help destroythe foam, thereby facilitating its removal.

The fracturing fluid preferably also comprises a gas, such as air ornitrogen, to foam the fluid. The gas also assists in the well clean-upprocess following breaking of the gel. Carbon dioxide can also be usedto create the foam, and can even be pumped ahead of the foam fracturingtreatment for purposes of (1) providing additional energy for fluidclean-up, (2) providing additional hydrostatic pressure above thatobtained through the use of nitrogen or air, (3) conditioning the coal,whereby the carbon dioxide has ability to displace methane adsorbed tothe coal.

Optionally, the fracturing fluid can further contain one or moreadditives such as additional surfactants, breaker aids, scaleinhibitors, and bactericides. The breaker aids serve as catalysts toincrease the breaker activity and performance at the lower bottomholetemperatures usually associated with fracturing coalbed methane wells.The composition can also contain an additive, such as a polyacrylamideor the like, that decreases the frictional pressure of pumping the fluidthrough the tubing, casing, tubing/casing annulus, surface lines, etc.

It is also possible to use a fracturing fluid composition that does notcontain any viscosifying agent. The fracturing fluid in this case couldjust contain water or brine, the foaming surfactant, and other necessaryadditives (such as biocides).

Techniques for hydraulically fracturing a subterranean formation will beknown to persons of ordinary skill in the art, and will involve pumpingthe fracturing fluid into the borehole and out into the surroundingformation. The fluid pressure is above the minimum in situ rock stress,thus creating or extending fractures in the formation.

In a typical fracturing process, the fracture is initiated by pumping anaqueous fluid with good to moderate leak-off properties, low polymerloadings and, typically, no proppant, into the formation. This initialfluid, referred to as a “pad”, is followed by a fracturing fluid ofhigher viscosity, carrying initially low quantities and then graduallyincreasing quantities of proppant into the fractures. Once the proppanthas been placed in the fractures, fracturing pressure is released andthe fractures partially close against the proppant which retains thefractures in a partially open, high permeability condition.

While compositions of the present invention are described herein ascomprising certain materials, it should be understood that thecomposition can optionally comprise two or more chemically differentsuch materials. For example, a composition could comprise a mixture oftwo or more foaming surfactants having the above-describedcharacteristics.

The present invention can be further understood from the followingexamples.

EXAMPLE 1

A wetting test was performed using a modification of the methoddescribed in API Bulletin RP 42. The procedure comprised:

1. Fill glass jar with 50 mL of 2% KCl and add surfactant.

2. Place 5 grams of crushed coal into the solution prepared in Step 1and mix for 60 seconds.

3. Decant the liquid from the slurry prepared in Step 2 into anotherglass jar.

4. Add 50 mL of dyed kerosene to the jar containing the decanted liquid.

5. Drop the coal solids into the jar prepared in step 4.

6. Observe the color and dispersibility of the coal particles.

The coal was in the form of large chunks of weathered (water wet)material. The surfactants used are summarized in Table 1.

TABLE 1 Surfactant Chemical description A branched tridecyl alcohol (7moles EO and 2 moles BO) B anionic ethoxylated ammonium fatty alcoholether sulfate C A cationic polymeric quaternary salt disclosed as apolyquat. D cationic blend of quaternary amine & alkanolamine Eanionic/cationic blend of quaternary amine & aromatic glycol ether Fcoco-aminopropionate G cationic quaternary amine

Surfactants C and F are both expected to possess an isoelectric pointsomewhere near a pH of 4.

All surfactants were tested at a concentration of 2 gallons ofsurfactant/thousand gallons of brine. The dyed kerosene was prepared bydissolving 0.1 g of dye in 700 mL of kerosene.

After performing the tests described above, the mixtures of brine,kerosene and coal particles were shaken vigorously for 10 seconds. Avideo camera was used to record results at 0, 15, and 30 minutes.

A foaming test was performed using the following procedure:

1. In a 1 L calibrated blender jar, add 1 mL of surfactant to 200 mL of2% KCl.

2. Set the Variac variable speed controller for Waring blender to zero,and set the blender to high.

3. Gradually increase the Variac setting until the greatest stable foamheight is reached. If the liquid bounces, reduce the Variac setting andslowly increase the setting until a stable foam height is reached. Holdat the maximum setting for 15 seconds.

4. Cut the power to the blender and immediately record the foam heightand start the timer.

Record the time required for 100 mL to accumulate in the bottom of theblender jar.

The results of the wetting and foaming tests are shown in Table 2 below.

TABLE 2 Wetting Good Foam Half-Life Experiment No. Surfactant PropertiesFoaming? (min:sec) 1-1 A Oil Wet No No foam 1-2 B Water Wet Yes 4:40 1-3C Water Wet Yes 3:20 1-4 D Water Wet Yes 4:20 1-5 E Water Wet Yes 3:001-6 F pH = 7 Oil Wet Yes 5:10 1-7 F pH = 5 Oil Wet Yes 4:00 1-8 G WaterWet Yes 4:10

As can be seen in Table 2, only surfactant F provided good oil wettingproperties and a stable foam. The samples were observed for 45 minutes.

Experiment 1-1

Previous testing of surfactant A, both in the laboratory and in thefield, has shown this additive to have superior de-watering propertiesfor coalbed methane wells, which increases the production of natural gasfrom such wells. The current testing of surfactant A again shows thatthis additive should enhance de-watering of coals due to very strongoil-wetting properties. Visual observation of the results of thisexperiment clearly showed coal fines being captured in the diesel phaseabove the oil-water interface. Larger wetted pieces of oil-wet coal wereheld at the interface by the strong wetting properties. The water phasewas exceptionally clear. This indicates that all of the coal wasattracted to the oil phase or settled to the bottom due to densitydifferences, demonstrating the strong oil-wetting tendencies ofsurfactant A. Finally, an evaluation performed on the coal at the bottomof the sample jar also indicated an oil-wet condition due to the strongclumping tendencies between the individual coal particles. When the jarwas tilted, the coal did not move until the jar bottom reached a veryhigh angle (>60°) and then the coal particles moved as a singlemass—indicating their strong attraction to one another.

Experiment 1-3

Surfactant C created a stable emulsion between the kerosene and waterphases. The water phase did not clear up within the 45-minute timeinterval, due in part to the emulsion and in part to the presence of thecoal fines. The heavy concentration of coal fines in the water phaseindicated that the coal was water-wet. Prior to the shaking step, theflow of the large coal particles was tested by tilting the jar, and inthis test the coal particles flowed freely without clinging to oneanother and moved at a relatively low angle (<45°). The free flowingnature of the particles in the water phase indicated water-wetting.

Experiment 1-4

Surfactant D showed strong water wetting of the coal, since there werefew, if any, coal particles at the interface, and most particles were inthe water phase. There was a heavy concentration of coal particlesattached to the sample jar within the water phase. Particles in thewater phase showed no tendency to clump when the sample jar was tilted,again indicating water-wetting properties.

Experiment 1-6

This experiment was conducted using surfactant F. A large quantity ofcoal particles could be seen in the oil phase, accumulating just abovethe oil-water interface, thus indicating strong oil wetting tendenciesof this surfactant. There were no fines dispersed throughout the waterlayer. Several large coal particles were even attracted to the oilphase. Buoyancy forces were able to move these large particles upward tothe oil face even after density differential initially sank theseparticles to the bottom of the jar. When tilted, the coal particlesclumped together at the bottom of the jar.

Experiment 1-8

This experiment used surfactant G. Though the sample was cloudy, it wasapparent that the material did not provide good oil wetting, as both theoil phase layer and the oil-water interface were essentially free ofcoal particles, and the coal fines in the water phase quickly settledwithout clumping. Some small coal fines could be seen sticking to thejar within the water phase, indicating water-wetting tendencies. Thecoal particles lying on the jar bottom flowed freely and independentlyof one another when the jar was tilted, again demonstrating a water-wetcondition for the coal particles.

Since only surfactant F met both the wetting and foaming criteria, itwas selected for further foam stability testing.

The foam stability tests were run with surfactant F at pH=7 and pH=5.The foam half-life was observed to be 5 minutes and 10 seconds at pH=7.The half-life dropped to 4 minutes at pH=5. The initial foam height wasalso less at the lower pH. When isopropyl alcohol was added tosurfactant F, the foam half-life at pH=7 was decreased to 4:40.

EXAMPLE 2

Tests were performed to assess the capability of the surfactant inmaintaining the relative permeability to water flowing through a columnof fresh coal. The procedure involved grinding or crushing coal intoparticles less than ¼-inch in size. This material was then packed into aPlexiglas tube and connected to a water source at the top end of thetube. The flow of water was maintained at a constant pressure dropthrough the pack and the amount of effluent was measured out the bottomof the pack as a function of time so that the permeability could becalculated. The average permeability of the column with less than ¼-inchcoal particles was around 10 darcies.

The coal for this testing was obtained from the Fruitland Coalformation, which is located in the San Juan Basin in New Mexico. Thecoal was obtained directly from an active mine and shipped in a sealedcontainer overnight to minimize the aging of the sample. Tests were runby establishing a baseline permeability to water through the pack andthen introducing one pore volume of the system to be evaluated.Following this addition, the flow of water through the pack wasreestablished and the change in permeability was noted. Another keyobservation was any coal fines that were transported through the packand seen in the effluent. This phenomenon is usually associated with asharp decrease in the permeability of the pack, indicating that theadditive has not maintained the natural oil-wet state of the coal andthus cannot prevent the mobilization of the fines.

The tests were centered on surfactant F; however, other tests wereperformed as a reference point to illustrate the benefit of thisadditive over conventional foaming agents. FIG. 1 shows the effect ofsurfactant F on the permeability of the coal pack at 2 and 4 gal/1000concentration. It is important to note that the recommendedconcentration for surfactant F as a foaming agent is 2 gal/1000. The 4gal/1000 concentration was tested to ensure there was no negative impactdue to overtreating. Based on visual observation it was noted that thereduction in permeability at the 4 gal/1000 concentration was mostlikely due to foam blockage in the permeability channels. This could bean effect of excess surfactant available or some other mechanism. Ateither concentration the results were very acceptable as the percentretained permeability was 95% for the 2 gal/1000 concentration and 80%for the 4 gal/1000.

The most common foaming agent being used today for fracturing coal seamreservoirs is anionic in nature (referred to herein as surfactant H;contains ethoxylated ammonium fatty alcohol ether sulfate at lowerconcentration than surfactant B) and typically added at a concentrationof 5 gal/1000. FIG. 2 shows the test results for one pore volume of thismaterial. There was a sharp decrease in permeability following theintroduction of surfactant to the pack. Visual observation also notedthe presence of coal fines in the effluent following the addition of thefluid containing the surfactant H. This effect, coupled with nearly a50% reduction in retained permeability, can have a very detrimentalimpact on the short and long-term productivity of a coalbed methanewell. The release of coal fines is indicative of a wettability changedue to the fact that wetted material will tend not to be mobilized inthe non-wetting phase. This simply means that the oil-wet coal fines(wetted material) will tend not to be mobilized in the water(non-wetting phase) flowing through the pack. If the wettability of thecoal surface and fines are altered, then it is possible for the fines tobe transported through the pack with the water.

One of the major issues with testing coal samples is the content(make-up) and chemical state of the coal being tested. Different coalswill give different results in terms of magnitude but the relativeeffect should remain the same. When surfactant A was developed, it wastested on many different types of coal that had undergone variousdegrees of weathering, etc. It was found that surfactant A would stillshow improved results in terms of flowing through the coal packregardless of the conditions. For this reason, it was decided to run atest with surfactant A and follow with surfactant F to see if the coalresponded normally to surfactant A and make sure that the surfactant Fwould still be effective. FIG. 3 shows the results of this test sequenceby adding one pore volume of surfactant A at 2 gal/1000 followed by onepore volume of surfactant F at the recommended concentration of 2gal/1000. The results indicate nearly 100% retained permeability underthese conditions. This test is relevant to pre-flushing a foamfracturing treatment with surfactant A, or to a refracturing treatmenton a well where surfactant A had been previously pumped.

The final test was to evaluate another anionic foaming agent (surfactantB), which is the most widely used foaming agent outside of coalbedmethane wells. The results, shown in FIG. 4, are very similar to thoseobtained with the anionic foaming agent used in fracturing coalbedmethane wells (surfactant H). As with the surfactant H, coal fines werevisually observed in the effluent following addition of the surfactantB. This mobilization of coal fines will be much more damaging underfield conditions where they can fill the wellbore above theperforations, requiring cleanout, plug and damage artificial liftequipment and block the cleat system which the are the arteries of thecoal system when it comes to producing fluids.

The preceding description of specific embodiments of the presentinvention is not intended to be a complete list of every possibleembodiment of the invention. Persons skilled in this field willrecognize that modifications can be made to the specific embodimentsdescribed here that would be within the scope of the present invention.

What is claimed is:
 1. A well treatment fluid composition, comprising acarrier fluid, a viscosifying agent, an amphoteric surfactant, andproppant, wherein the surfactant has the formula R—NH₂—(CH₂)_(n)—C(O)OXwherein R is a saturated or unsaturated alkyl group having from 6-20carbon atoms, n is from 2-6, and X is hydrogen or a salt forming cation.2. The composition of claim 1, wherein the composition is a foam thatcomprises a gas selected from the group consisting of nitrogen, air, andcarbon dioxide.
 3. The composition of claim 1, wherein n is from 2-4. 4.The composition of claim 1, wherein R is a saturated or unsaturatedalkyl group having from 10-14 carbon atoms.
 5. The composition of claim1, wherein the surfactant comprises an alkyl-aminopropionic acid orpropionate.
 6. The composition of claim 1, wherein the surfactant is acoco-aminopropionate.
 7. The composition of claim 1, wherein theviscosifying agent is a solvatable, crosslinkable polymer selected fromthe group consisting of guar, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, hydroxyethyl cellulose,carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan,and mixtures thereof.
 8. The composition of claim 7, further comprisinga crosslinking agent.
 9. The composition of claim 7, further comprisinga gel breaker for the viscosifying agent.
 10. The composition of claim9, further comprising a breaker aid.
 11. The composition of claim 1,further comprising an additive that decreases the frictional pressureinvolved in pumping the fluid composition through well tubing.
 12. Thecomposition of claim 11, wherein the additive comprises at least onepolyacrylamide.
 13. A well treatment fluid composition, comprising acarrier fluid; a viscosifying agent selected from the group consistingof guar, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, hydroxyethyl cellulose,carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan,and mixtures thereof; a coco-aminopropionate surfactant; and proppant.